A widely used technique for searching for oil or gas is the seismic exploration of subsurface geophysical structures. Reflection seismology is a method of geophysical exploration to determine the properties of a portion of a subsurface layer in the earth, which information is especially helpful in the oil and gas industry. The seismic exploration process consists of generating seismic waves (i.e., sound waves) directed toward the subsurface area, gathering data on reflections of the generated seismic waves at interfaces between layers of the subsurface, and analyzing the data to generate a profile (image) of the geophysical structure, i.e., the layers of the investigated subsurface. This type of seismic exploration can be used both on the subsurface of land areas and for exploring the subsurface of the ocean floor.
Marine reflection seismology is based on the use of a controlled source that sends energy waves into the earth, by first generating the energy waves in or on the ocean. By measuring the time it takes for the reflections to come back to one or more receivers (usually very many, perhaps in the order of several dozen, or even hundreds), it is possible to estimate the depth and/or composition of the features causing such reflections. These features may be associated with subterranean hydrocarbon deposits.
For marine applications, seismic sources are essentially impulsive (e.g., compressed air is suddenly allowed to expand). One of the most used sources is air guns. The air guns produce a high amount of acoustics energy over a short time. Such a source is towed by a vessel either at the water surface or at a certain depth. The acoustic waves from the air guns propagate in all directions. A typical frequency range of the acoustic waves emitted by the impulsive sources is between 6 and 300 Hz. However, the frequency content of the impulsive sources is not fully controllable and different sources are selected depending on the needs of a particular survey. In addition, the use of impulsive sources can pose certain safety and environmental concerns. Thus, another class of sources that may be used is marine vibratory sources. The marine vibrator (or air gun) can also generally be referred to as a “source,” i.e., a source of the sound/energy waves that are transmitted and then reflected/refracted off the ocean floor and then received by one or more, usually dozens, of receivers.
Marine vibratory sources, including hydraulically powered sources and sources employing piezoelectric or magneto-strictive material, have been used in marine operations. A marine vibrator generates a long tone with a varying frequency, i.e., a frequency sweep. This signal is applied to a moving port, e.g., a piston, which generates a corresponding seismic wave. Instantaneous pressure resulting from the movement of plural pistons corresponding to plural marine vibrators may be lower than that or an airgun array, but total acoustic energy transmitted by the marine vibrator may be similar to the energy of the airgun array due to the extended duration of the signal. However, such sources need a frequency sweep to achieve the required energy.
It is known by those of skill in the art of seismic exploration that an appropriate choice of frequencies of the frequency sweep is needed to drive the sound producing device that generate seismic waves whose reflections can, in turn, be used to determine the possible or probable location of hydrocarbon deposits under, e.g., the ocean floor. Sweep design pertains to the choice of frequencies used to drive a sound producing device used for determining the possible or probable location of hydrocarbon deposits under, e.g., the ocean floor. A sweep is a sinusoid with a continuously variable frequency, and can be defined by its amplitude A(f), its begin and end frequency, and its sweep rate Sr(f). Provided the sweep is long enough (longer than 5 or 6 seconds), the amplitude spectrum of the sweep at frequency f is proportional to A(f) and to the square root of Sr(f). Target-oriented sweep design (i.e., searching for a particular known type of hydrocarbon, in a particular known type of geological formation) consists in defining A(f) and Sr(f) to obtain the desired Signal-to-Noise ratio (SNR) of the target reflection.
Non-linear sweeps were introduced in late 1970s. At that time, the purpose of these sweeps was to generate a higher proportion of high frequencies that are attenuated by non-elastic wave propagation. The limited flexibility of the available software allowed the choice between a very small amplification, which did not significantly differ from conventional linear sweeps, and larger amplifications, which being constant over the entire frequency range often resulted in a damaging reduction in the low frequency content. This drawback was noticed and more sophisticated electronics were developed to allow more flexibility. An example of such a technique contributing to an enhancement was shown by D. Mougenot in 2002, as shown in FIG. 3. FIG. 3 illustrates a comparison of conventional (line A) and segmented logarithmic sweeps (line B). It can be readily observed in FIG. 3 that line A represents a linear rate of change of the sweep frequency, beginning at about 10 Hz, and changing linearly to about 120 Hz, over a 20 second period of time. Note that the relative amplitude of the transmitted signal also changes over time, from about 10-15 dB to about 55 dB by the end of the sweep period. The sweep proposed by Mougenot and Meunier in 2002 began at about 10 Hz, and proceeds to about 43 Hz over a two second period of time, but at about a constant (or linear) gain of 35 dB. Then, the sweep frequency changes from about 43 Hz to about 71 Hz over a two second period of time, and changes in amplitude from about 35 dB to about 37-38 dB. Finally, in the last phase, the sweep frequency changes from about 71 Hz at about 37-38 dB to 133 Hz and just over 60 dB in a 26 second time period. With such a change in the amplitude and frequencies over time, some gains were realized in maintaining low frequency content, without sacrificing the higher frequency affects. However, even with the realized benefits, there remained problems with the sweep frequencies. These problems include stroke limitations (i.e., the length of the movement of the piston) in the generation of low frequencies, and various physical constraints of the seismic vibrator and/or medium within which it operates,
Marine vibrators (herein after referred to as “vibrators,” “marine vibrators,” and/or “seismic vibrators,” or more simply as “sources”) can be implemented in what are referred to as “towed arrays” of the plurality of sources and their receivers, wherein each towed array can include numerous vibrators, numerous receivers, and can include several or more groups of receivers, each on its own cables, with a corresponding source, again on its own cable. Systems and methods for their use have been produced for devices that can maintain these cables, for example, in relatively straight lines as they are being towed behind ships in the ocean. As those of ordinary skill in the art can appreciate, an entire industry has been created to explore the oceans for new deposits of hydrocarbons, and has been referred to as “reflection seismology.”
For a seismic gathering process, as shown in FIG. 1, a data acquisition system 10 includes a ship 2 towing plural streamers 6 that may extend over kilometers behind ship 2. Each of the streamers 6 can include one or more birds 13 that maintains streamer 6 in a known fixed position relative to other streamers 6, and the birds 13 are capable of moving streamer 6 as desired according to bi-directional communications birds 13 can receive from ship 2. One or more source arrays 4a,b may be also towed by ship 2 or another ship for generating seismic waves. Source arrays 4a,b can be placed either in front of or behind receivers 14, or both behind and in front of receivers 14. The seismic waves generated by source arrays 4a,b propagate downward, reflect off of, and penetrate the seafloor, wherein the refracted waves eventually are reflected by one or more reflecting structures (not shown in FIG. 1) back to the surface (see FIG. 2, discussed below). The reflected seismic waves propagate upwardly and are detected by receivers 14 provided on streamers 6. This process is generally referred to as “shooting” a particular seafloor area, and the seafloor area can be referred to as a “cell”.
FIG. 2 illustrates a side view of the data acquisition system 10 of FIG. 1. Ship 2, located on ocean surface 46, tows one or more streamers 6, that is comprised of cables 12, and a plurality of receivers 14. Shown in FIG. 2 are two source streamers, which include sources 4a,b attached to respective cables 12a,b. Each source 4a,b is capable of transmitting a respective sound wave, or transmitted signal 20a,b. For the sake of simplifying the drawings, but while not detracting at all from an understanding of the principles involved, only a first transmitted signal 20a will be shown (even though some or all of source 4 can be simultaneously (or not) transmitting similar transmitted signals 20). First transmitted signal 20a travels through ocean 40 and arrives at first refraction/reflection point 22a. First reflected signal 24a from first transmitted signal 20a travels upward from ocean floor 42, back to receivers 14. As those of skill in the art can appreciate, whenever a signal—optical or acoustical—travels from one medium with a first index of refraction n1 and meets with a different medium, with a second index of refraction n2, a portion of the transmitted signal is reflected at an angle equal to the incident angle (according to the well-known Snell's law), and a second portion of the transmitted signal can be refracted (again according to Snell's law).
Thus, as shown in FIG. 2, first transmitted signal 20a generates first reflected signal 24a, and first refracted signal 26a. First refracted signal 26a travels through sediment layer 16 (which can be generically referred to as first subsurface layer 16) beneath ocean floor 42, and can now be considered to be a “new” transmitted signal, such that when it encounters a second medium at second refraction/reflection point 28a, a second set of refracted and reflected signals 32a and 30a, are subsequently generated. Further, as shown in FIG. 2, there happens to be a significant hydrocarbon deposit 44 within a third medium, or solid earth/rock layer 18 (which can be generically referred to as second subsurface layer 18). Consequently, refracted and reflected signals are generated by the hydrocarbon deposit, and it is the purpose of data acquisition system 10 to generate data that can be used to discover such hydrocarbon deposits 44.
The signals recorded by seismic receivers 14 vary in time, having energy peaks that may correspond to reflectors between layers. In reality, since the sea floor and the air/water are highly reflective, some of the peaks correspond to multiple reflections or spurious reflections that should be eliminated before the geophysical structure can be correctly imaged. Primary waves suffer only one reflection from an interface between layers of the subsurface (e.g., first reflected signal 24a). Waves other than primary waves are known as multiples. Surface multiple signal 50a shown in FIG. 2 is one such example of a multiple, but as shown in FIG. 3, there are other ways for multiples to be generated.
As illustrated in FIG. 3, seismic source 4 produces first transmitted wave 20a that splits into a primary transmitted wave 26a (referred to also as first refracted signal) penetrating inside first subsurface layer 16 (referred to also as “sediment layer” though that does not necessarily need to be the case) under ocean floor 42, and first reflected signal 24a that becomes surface multiple signal 50 after it interfaces with ocean surface 46 (or fourth interface). Second transmitted wave 20b is reflected once at second interface 48 and becomes second reflected signal 24b, and then is reflected down again at ocean floor 42 to become internal multiple signal 51. Internal multiple signal 51 and surface multiple signal 50 also reaches receiver 14, but at different times. Thus, receiver 14 can receive at least several different signals from the same transmitting event: second reflected signal 30a, surface multiple signal 50, and internal multiple signal 51.
As is apparent from FIG. 3, the timing of the received signals will depend on the depth of the ocean 40, its temperature, density, and salinity, the depth of sediment layer 16, and what it is made of.
Thus, receiver 14 can become “confused” as to the true nature of the subsurface environment due to reflected signals 30, and multiple signals 50, 51. As briefly discussed above, other multiples can also be generated, some of which may also travel through the subsurface. A multiple, therefore, is any signal that is not a primary reflected signal. Multiples, as is known by those of ordinary skill in the art, can cause problems with determining the true nature of the geology of the earth below the ocean floor. Multiples can be confused by data acquisition system 10 with first, second or third reflected signals. Multiples do not add any useful information about the geology beneath the ocean floor, and thus they are, in essence, noise, and it is desirable to eliminate them and/or substantially reduce and/or eliminate their influence in signal processing of the other reflected signals so as to correctly ascertain the presence (or the absence) of underground/underwater hydrocarbon deposits.
Internal multiple signals 51 typically arise due to a series of subsurface impedance contrasts. They are commonly observed in seismic data acquired in various places, such as the Santos Basin of Brazil. They are often poorly discriminated from the primaries (i.e., the first, second and third reflected signals, among others), because they have similar movement, dips and frequency bandwidth, thereby making attenuation and/or elimination of internal multiple signals 51 (as well as surface multiples 50) one of the key issues in providing clear seismic images in interpreting areas of interest. Over time, various methods have been developed to address this difficult problem and most of them rely on the ability to identify the multiple generators.
As those of skill in the art can further appreciate, numerical simulations of elastic wave propagation algorithms are the critical components for seismic imaging and inversion. Following the data collection as described in detail above, it is the processing of the collected data that yields tangible, real results, albeit displayed on a computer screen and/or printed, that shows where hydrocarbons are probably located, and equally important, where they are not. It is known that marine seismic data can be interpreted to be an image or representation of the elastic properties of the different sub-surface components and the ocean water, and must be transformed from a scalar or vector quantity, recorded in time, to spatial quantities representing some useful attribute of the reservoir, or sub-surface areas. Ideal “elastic waves” are a mechanical disturbance that propagates through a material, causing oscillations of the particles of that material about their equilibrium positions but no other change, changes in position of, or deformation of, the material itself. Numerous methods exist for interpreting data presuming behavior that conforms to elastic wave propagation. There are numerous problems, however, with these known methods. Some of these methods include finite difference schemes and pseudo-spectral algorithms. Finite-difference methods (or schemes) are numerical methods for approximating the solutions to differential equations using finite difference equations to approximate derivatives. Finite-difference schemes exhibit high efficiency in obtaining results, but cannot ensure the accuracy of high frequency components; thus, their utility in marine seismic analysis can be somewhat limited. Pseudo-spectral algorithms are accurate up to the Nyquist frequency, but their efficiency depends on the optimization of the Fast Fourier transform (FFT) algorithm. Conventional FFT algorithms are optimized for signal processing (usually in communications systems), in which the problems are generally one dimensional time series. Accordingly, it would be desirable to provide methods, modes and systems optimizing interpretation of elastic wave propagation data in marine seismic data collection systems and devices.